It has long been known that only a portion of the total crude oil present in a reservoir can be recovered during a primary recovery process, this primary process resulting in oil being recovered under the natural energy of the reservoir. The reservoir typically takes the form of an oil-bearing subterranean rock formation having sufficient porosity and permeability to store and transmit fluids, and with which oil is associated, for example being held in pores or between grains of the rock formation. So-called secondary recovery techniques are used to force additional oil out of the reservoir, the simplest method of which is by direct replacement with another medium in the form of a displacement fluid, usually water or gas. Enhanced oil recovery (EOR) techniques can also be used. The purpose of such EOR techniques is not only to restore or maintain reservoir pressure, but also to improve oil displacement in the reservoir, thereby minimising the residual oil saturation of the reservoir, that is, the volume of oil present in the reservoir. Where the initial reservoir pressure is close to the bubble point of the crude oil, secondary or enhanced oil recovery techniques may be used early in the life of a field, for example, primary recovery may not occur.
“Waterflooding” is one of the most successful and extensively used secondary recovery methods. Water is injected, under pressure, into reservoir rock formations via injection wells. The injected water acts to help maintain reservoir pressure, and sweeps the displaced oil ahead of it through the rock towards production wells from which the oil is recovered. The water used in waterflooding is generally saline water from a natural source such as seawater or may be a produced water (i.e. water that is separated from the crude oil at a production facility).
It is also known that the use of a lower salinity injection water during water-flooding can increase the amount of oil recovered compared to the use of a higher salinity water. It is also known that reducing the multivalent cation content of a lower salinity injection water can have an impact on the oil recovery. However, lower salinity waters, such as fresh water, are often not available at a well site, for example at offshore oilfields, and have to be made by reducing the total dissolved salt (TDS) concentration and/or the concentration of multivalent cations of a source water using desalination techniques such as reverse osmosis or forward osmosis. Source waters that are known to be treated in this manner include seawater, brackish water, produced water and aquifer water.
“Lower” or “low” salinity water is hereinafter intended to define water having a total dissolved solids content (TDS) in the range of 200 to 15,000 ppmv, preferably, 500 to 12,000 ppmv. Where the formation rock contains swelling clays, in particular, smectite clays, a relatively high TDS for the low salinity water is required in order to stabilise the clays, thereby avoiding the risk of formation damage. Thus, where the formation rock contains an amount of swelling clays sufficient to result in formation damage, the low salinity water preferably has a total dissolved solids content (TDS) in the range of 8,000 to 15,000 ppmv, in particular, 8,000 to 12,000 ppmv. Where the formation comprises amounts of swelling clays that do not result in formation damage, the TDS of the source water is typically in the range of 200 to 8,000 ppmv, preferably 500 to 8,000 ppmv, for example, 1,000 to 5,000 ppmv. As discussed above, the low salinity water also has a low concentration of multivalent cations of typically 40 ppmv or less, preferably less than 35 ppmv, more preferably, less than 30 ppmv, for example, less than 25 ppmv. However, it is preferred that the low salinity water contains at least some multivalent cations. Thus, a multivalent cation content of the low salinity water in the range of 5 to 40 ppmv, preferably, 10 to 40 ppmv is acceptable.
The water present in the pore space of a rock, hereinafter referred to as “formation water”, can vary in composition. Where a displacement fluid is injected without performing primary recovery or immediately after primary recovery, the formation water will typically comprise connate water, and where a displacement fluid is injected after a previous waterflood, the formation water will typically comprise a mixture of connate water and a previously injected water such as sea water or produced water.
The factors that control the interactions between crude oil, the rock formation, the injection or displacement fluid and the formation water, and their effect on wettability and oil recovery, involve complex and sometimes competing mechanisms. It has also been found that a factor in improving oil recovery during a low salinity waterflood is the use of an injection water of a lower multivalent cation content or concentration than that of the formation water. Thus, greater oil recovery is achieved when the ratio of the total multivalent cation content of the aqueous low salinity displacement fluid to the total multivalent cation content of the formation water is less than 1, for example, less than 0.9. Generally, the lower the ratio of the total multivalent cation content of the aqueous low salinity displacement fluid to the total multivalent cation content of the formation water (hereinafter “multivalent cation ratio for the low salinity aqueous displacement fluid”), the greater the amount of oil that is recovered from a particular formation. Thus, the multivalent cation ratio for the low salinity aqueous displacement fluid is preferably less than 0.8, more preferably, less than 0.6, yet more preferably, less than 0.5, and especially less than 0.4 or less than 0.25. The multivalent cation ratio for the low salinity aqueous displacement fluid may be at least 0.001, preferably, at least 0.01, most preferably, at least 0.05, in particular at least 0.1. Preferred ranges for the multivalent cation ratio for the low salinity aqueous displacement fluid are 0.01 to 0.9, 0.05 to 0.8, but especially 0.05 to 0.6 or 0.1 to 0.5.
It is also possible to inject a slug of low salinity water of controlled oil reservoir pore volume, PV. The term “pore volume” is used herein to mean the swept volume between an injection well and a production well and may be readily determined by methods known to the person skilled in the art. Generally, the pore volume (PV) of the slug of low salinity water is at least 0.2 PV, as a slug of lower pore volume tends to dissipate in the formation and may not result in appreciable incremental oil production. It has also been found that where the pore volume of the softened injection water is at least 0.3, preferably, at least 0.4, the slug tends to maintain its integrity within the formation (does not disperse within the formation) and therefore continues to sweep displaced oil towards a production well. Thus, the incremental oil recovery for a particular formation approaches a maximum value with a slug of at least 0.3 PV, preferably at least 0.4 PV, with little additional incremental oil recovery with higher pore volume slugs.
Although, it is possible to continue to inject the low salinity water into a formation, typically, the pore volume of the slug of low salinity water is minimized since there may be limited injection capacity for the low salinity water owing to the need to dispose of produced water. Also, there may be limited availability of a naturally occurring low salinity water or where the low salinity water is produced using desalination techniques, the capacity of the desalination equipment may be limited owing to operation costs and weight considerations (where the desalination plant is located on a platform or floating production, storage and off-loading (FPSO) facility). Thus, the pore volume of the low salinity water is preferably less than 1, more preferably less than 0.9 PV, most preferably, less than 0.7 PV, in particular, less than 0.6 PV, for example, less than 0.5 PV. Typically, the slug of low salinity water has a pore volume in the range of 0.2 to 0.9, preferably 0.3 to 0.6, and especially 0.3 to 0.45. After injection of a pore volume of the low salinity water that achieves close to the maximum incremental oil recovery (preferably, a slug of softened injection water having a pore volume of less than 1), a drive (or post-flush) water of higher multivalent cation content and/or higher TDS, usually both, may be injected into the formation (for example, seawater or a high salinity produced water) thereby ensuring that the slug of softened injection water (and hence the released oil) is swept through the formation to the production well. In addition, the injection of the post-flush water may be required to maintain the pressure in the reservoir. After injection of a pore volume of the low salinity water that achieves close to the maximum incremental oil recovery, the low salinity water may be injected into a different hydrocarbon-bearing formation of the oil reservoir or into a hydrocarbon-bearing formation of a different oil reservoir.
It has also been found that enhanced oil recovery using low salinity water is dependent upon the nature of the formation that contains the crude oil and formation water. Thus, it is preferred that the formation comprises a sandstone rock and at least one mineral that has a negative zeta potential under the formation conditions.
Currently, laboratory core flood testing (where a sample of rock is removed from a reservoir, before oil production begins or during primary recovery, and is then placed under the reservoir conditions for testing in the laboratory) or single well chemical tracer testing (where a fluid labelled with appropriate chemical tracers is injected into a formation via an injection well and produced back from the same well) are applied in order to determine the residual oil saturation of the formation following a low salinity waterflood, and based on the results, a decision can be made as to whether or not a waterflood using lower salinity water is worthwhile. These tests are time consuming and the results are often not available during the planning stage of an oil field development. Accordingly, in the absence of tests results showing enhanced oil recovery using a low salinity waterflood, there may be a reluctance to include desalination equipment in the design for the production facility.